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First Solar ‘Furloughs’ Half its AVSR1 Workforce

2012-05-26T18:15:54+00:00

The 230-megawatt Antelope Valley Solar Ranch One (AVSR1) photovoltaic power plant being built for Exelon Corporation (NYSE: EXC) by First Solar (Nasdaq: FSLR) is facing some challenges.

Exclusively to GTM, Assistant Los Angeles County Supervisor Norm Hickling confirmed rumors of “a large layoff” of the AVSR1 workforce on Friday. “I also understand negotiations continue,” Hickling added about attempts to settle the dispute between First Solar and LA County that has put the project six weeks behind schedule, with “little progress.”

Approximately 120 of the current 240 person workforce was “furloughed,” according to First Solar Public Relations Director Alan Bernheimer.

This is a severe blow to an already jobs-poor Los Angeles-adjacent community where recent studies found as many as one in three homeowners behind and/or underwater with their mortgages.

Negotiations began in early April after an LA County safety inspector discovered that electrical connections on the 3.7 million First Solar cadmium telluride (CdTe) thin film photovoltaic panels that were to be used at the site did not have the Underwriters Laboratory (UL) approval required by the project’s County-granted Conditional Use Permit (CUP).

The inspector was reportedly doing a routine site visit, in service to the CUP, when he discovered there was no UL approval for the panels’ electrical connections.

State of California building and safety codes require UL approval of electrical connectors. That approval is apparently not required or its absence was not noticed in other states, such as Nevada, where First Solar has done thin film installations. It is also a standard to which First Solar has not been held at installations it has done elsewhere in California.

Neither the County nor First Solar have offered many details. “The Los Angeles County Public Works Department,” County spokesperson Bob Spencer told GTM when negotiations began, “is working with First Solar to address its plan check comments relative to the rating of the modules and the applicable electrical safety regulations.”

“First Solar is in discussions with Los Angeles County Public Works regarding electrical codes and standards interpretations as they relate to utility-scale, solar photovoltaic (PV) installations,” First Solar spokesperson Ted Meyer told GTM at that time. “We are confident these discussions will result in a satisfactory resolution.”

That was six weeks ago.

“Our discussions with the county are ongoing and we are working to resolve the issue so we can put people back to work,” Bernheimer told GTM Saturday.

First Solar spokesman Adam Eventov told the Oso Town Council on Thursday night a settlement was expected by mid-June but noted, in the same statement, that problems with dust were preventing the company from continuing to grade land and prepare racks for panel installation at the project site. A proposal to use decomposed granite to minimize dust had been blocked by the County, Eventov said, leaving them with only the expensive alternative of hydroseeding.

Eventov also said that First Solar has, as promised, made a $140,000 donation to Antelope Valley College on behalf of the AVSR1 project but continues to hold a matching donation to the local communities until panel installation can continue.

At the same meeting, elected members of the Oso Town Council Richard Skaggs and Gerry Conroy, just back from the annual First Solar shareholder meeting in Phoenix, reported to the community that they thought the County was more responsible for impediments to continued construction than the company.

Panel installation was scheduled to begin at AVSR1 by mid-April. If the panels cannot be approved until UL certification is obtained or replacement with another technology becomes necessary, the financial consequences for First Solar could be problematic to the already financially hamstrung company. First Solar’s share price was as high as $140 in July 2011 but now hovers around $15.

First Solar continues to be in charge of engineering, procurement and construction (EPC) at the site. It is also in charge of EPC at the NRG Energy Alpine Solar project located a few miles away which, like AVSR1, would use the problematic panels and is subject to provisions of an LA County CUP.

The total number of panels that will require some kind of attention or adjustment is well in excess of four million.

Neither the County nor First Solar would comment on whether corrections at other First Solar projects in development or retroactive corrections of panels at other California sites will be necessary.

Also under development with First Solar as panel supplier and in the EPC role and -- therefore potentially affected by this issue -- are the 550-megawatt Topaz Solar Farm in San Luis Obispo County owned by MidAmerican Holdings and the 550-megawatt Desert Center Solar Farm in Riverside County owned by NextEra Energy and GE.

The 21-megawatt Blythe Solar Project in Riverside County owned by NRG Energy may also be affected.

With a power supply uncertainty looming due to the safety issues that took the 2,200 megawatt Son Onofre Nuclear Generating Station (SONGS) off line, it would have been a positive result for Southern California if AVSR1 was coming online this summer.

GTM Podcast: Solar VC Recap, GTM Analysts on China Solar Anti-Dumping Case

2012-05-25T17:00:56+00:00

The global solar industry will be undergoing shifts in cost and supply chain structure as a result of the anti-dumping ruling from the Department of Commerce.

In today's podcast, GTM Solar Analyst team members, Shyam Mehta and Shayle Kann discuss the gory details of the ruling's impact. Scott Clavenna, Greentech Media's CEO, leads the discussion. We also cover the recent run of funding in solar and give thanks and props to some of GTM's many article commenters.

We look forward to providing these podcasts as a regular feature and bringing you the events of the week in a different format. You'll hear from GTM research analysts, editors, reporters and the occasional special guest. Stay tuned.

How Chinese Solar Manufacturers Can Benefit From the New US Tariff

2012-05-25T16:00:36+00:00

Spire Corporation’s Spire Solar unit builds turnkey factory assembly lines for crystalline and thin-film photovoltaic (PV) factories. Roger Little, Spire’s CEO, is looking pretty smart right now.

Since early this spring, Little has been predicting a tariff in the 30 percent range would be put on Chinese solar panel imports. On May 17, the U.S. Department of Commerce imposed a 31 percent tariff on panels from China’s biggest panel makers.

U.S. solar manufacturers have been struggling against low-price panels from China. The tariff is intended to prevent what domestic trade groups have described as “dumping” by the Chinese of below-production-cost products. Chinese panel makers are attempting to unload excess inventory even though they are being forced to do so at a loss.

There are two parts to the Commerce Department tariff, one punitive and one preventative. The 61 Chinese companies identified with the dumping will be required to pay the 31 percent tariff. To prevent those companies from shipping into the U.S. under a false front, Chinese panel makers who have not been exporting to the U.S. will be required to pay a 250 percent tariff if they begin doing so.

Some say Chinese manufacturers are likely to get around the tariffs by using a non-Chinese false front. Others fear China will counter-accuse U.S. polysilicon manufacturers of unfair practices before the World Trade Organization.

Media reports say Chinese solar company stock prices fell with the Commerce Department announcement while U.S. panel makers’ share prices rose.

“From a broad view,” Little recently told GTM, referencing data that put the U.S. imported price of a Chinese module at 94 cents per watt, “a tariff would not be good for the industry because it would likely result in higher-priced modules.” But, as with the cost of Spire’s turnkey facilities, Little said, variables make all the difference.

In the same assessment from which he got the 94 cents per watt Chinese module price, Little found that U.S. manufacturers would require a 31 percent tariff if they were to import Chinese wafers to manufacture modules. The wafer price would be 35 cents, the wafer to module conversion cost would be 88 cents and the U.S.-made module would cost $1.23.

Domestic manufacturers would, however, only need a 14 percent tariff if they were to import Chinese solar cells at 53 cents to make modules. The cell-to-module conversion would cost 54 cents, making the cost of a U.S. module $1.07.

And, Little found, if a U.S. manufacturer were to import laminates at 70 cents, a laminate-to-module conversion cost of 24 cents would make the price of a U.S. module cost 94 cents and no tariff would be needed.

Spire offers turnkey assembly lines that perform all three of those manufacturing processes.

Spire, Little said, will continue to thrive despite the tariff. They have customers all over the world. They rode the Chinese expansion of the last few years very successfully and have turned their attentions more recently to India, where a 20,000-megawatt solar target, incentive programs and an entrepreneurial inclination are sparking a major expansion. His company has also recently done business in such disparate and expanding markets as Ethiopia, Turkey and Romania.

“We know what’s going on all over the world,” Little acknowledged. He had no fear of a backlash or a trade war from the tariff but, in fact, saw it as an opportunity.

Germany-based SolarWorld and Japan-based Sharp, which according to Little dominate the U.S. crystalline silicon PV market, obtain their manufacturing equipment in their home markets. Spire, Little said, therefore has no chance to win their business.

A tariff, though, will bring new customers. “We talk to the top ten Chinese manufacturers,” Little said. “We have a come-to-America program. We’ll give you the machines, we’ll set you up, we’ll help you do the whole thing in America.”

Ultimately, Little said, the real problem will come if the tariff impedes the advance of the levelized cost of solar energy-generated electricity in the U.S. and around the world toward grid parity.

Module prices may rise, Little predicted, but a healthy competition will return to the broader solar sector and that could drive prices down. “I would’ve loved to have seen the concentrated solar cell (CPV) market take off. But CPV has the same problem everyone else has,” he explained. “There’s no traction because of these 88-cent modules coming in.”

Parity, Little said, is “a systems-driven equation.” The total calculation could remain competitive, he insisted. “If you start with the laminate, you can compete right now.” But, he said, if you want to start with cells, it’s going to cost you a little more.”

To keep the price low, U.S. manufacturers have to learn where the competitive point to enter the value chain is, Little said. “That’s the whole point.”

The tariff will also shift the international market, Little acknowledged. Chinese laminate manufacturers will find a ready market in the U.S. but cell and wafer manufacturers “will have a difficult time being competitive” unless the tariff drives them “to manufacture in the U.S.” Likewise, he added, with the knowledge of where to enter the values chain, domestic manufacturers “can compete then, too.”

Less Coal, But More What?

2012-05-25T15:00:47+00:00

It’s not hot yet across the entire U.S., but it soon will be. Power plant rules haven’t changed yet, but they will.

With the unofficial start of summer just around the corner, utilities and independent system operators are looking for ways to relieve peak loads and congestion on the electricity grid for the coming season and down the road.

Although every region of the country claims it has adequate generation for even the hottest days of summer, each ISO is also looking forward as U.S. Environmental Protection Agency rules will take affect in coming years.

Grid operators are planning now for how to replace coal with natural gas, along with a side of demand response and a dash of renewables. Many of the changes won’t come for years, but the planning is happening now and changes to pricing and rules, will happen ahead of the EPA rules.

“From a PJM perspective, the lights aren’t going to go out,” Paul Sotkiewicz, chief economist  at PJM Interconnection, said during a Restructuring Today webinar on Wednesday.

There are two EPA rules that are putting pressure on older coal generation, the cross-state air pollution rule, which is currently on stay until further ruling, and the MATS rule, which regulates mercury and other heavy metals and is scheduled to go into effect in April 2015.

PJM Invests in Transmission

In PJM’s territory, the problem is not a lack of capacity. Sotkiewicz said that there’s quite a bit of natural gas that isn’t being used to its full capacity. PJM expects that nearly 14,000 megawatts of coal-fired generation will retire by 2016. Most of the plants are over 40 years old or 400 megawatts or less, which makes up about 30 percent of PJM’s current coal fleet.

In anticipation of the changes, the capacity auctions for the 2015 to 2016 year in PJM territory procured a record amount of new generation for one year, nearly 5,000 megawatts. Almost all of the new generation is gas-fired. For the first time ever, new combined-cycle gas plants are the same price as a northern Appalachian coal plant, according to Joseph Bowring, independent market monitor for PJM and president of Monitoring Analytics.

Overall, PJM has 164,561 megawatts of capacity resources. Along with new gas resources, the capacity auction procured nearly 15,000 megawatts of demand response and energy efficiency. Energy efficiency, solar and wind saw double-digit growth since the year before, although the renewables are still just a drop in the bucket in terms of generation. Solar, for example, increased to 56 megawatts, a 22 percent increase from the year before.

To combat retiring coal generation, PJM recently announced $2 billion in transmission upgrades. There will be more than 130 projects that range from substation upgrades to rebuilding transmission lines. More than half the projects will be in Ohio, where there is a lot of coal retiring. However, the upgrades could also be a boon to renewables like wind, which has various transmission constraints.

MISO Seeks More Wind, Demand Response

The Midwest Independent System Operator is facing essentially the same problem as PJM, although it is even more pronounced, since more than 70 percent of its fleet is coal-fired. MISO also has transmission constraints that are being revisited, but there have been no announcements about upgrades similar to what PJM is doing.

The constraints will mean a change to demand response rules, said Jameson Smith, manager of regulatory studies at MISO. “Demand response qualification requirements and deployment procedures will be reviewed and given a potential increase in use.”

For MISO, there’s more wind that’s currently slated to be built than gas, but that could also change in coming years, said Smith. Any new gas could need new pipeline infrastructure, which can take at least five years to develop. At this time, “there’s limited ability to increase existing gas-fired unit capacity,” said Smith. But wind needs transmission too, which means that no matter what comes on-line to replace coal in the next five years, there will have to be substantial investment.

ERCOT Pushes Up Prices

In Texas, ERCOT is already planning to spur new generation by raising the system-wide offer cap. Last summer, prices hit $2,500 per megawatt-hour as ERCOT’s grid was strained by high temperatures. If a ruling now being considered is approved, that could jump to at least $4,000 as early as this August, and perhaps rise considerably more in coming years. “There’s a consensus that the system-wide offer cap will have to go significantly higher,” Ken Anderson, commissioner of the public utility commission of Texas, said during a Restructuring Today webinar. “We need to at least double it -- and maybe triple it.”

A bump to the SWOC will also come with a change to a variety of other rules, including a potential increase of 200 megawatts to come from energy efficiency programs and a decision that could allow waste gas and energy storage to play in ERCOT’s markets. The cost of a negawatt is still considerably cheaper than building new generation.

Anderson said that he believed that the commission was removing most of the barriers to energy storage coming into the wholesale market, and now it was just a matter of economics. The next few years will also be rosier for negawatts. “Eventually, I’d like to get demand response out of energy efficiency completely and into the competitive space,” he said during the webinar. “We need to give some certainty to where the market will be in 2014, 2015 and beyond.”

Huge Win for California Solar: CPUC Keeps Net Energy Metering Alive

2012-05-24T18:36:51+00:00

A fight over the future of net energy metering (NEM) in California was resolved by a California Public Utilities Commission (CPUC) May 24 decision on the arcane question of how to define the NEM cap. The definition of the cap had become a battleground over NEM pitting Investor Owned Utilities (IOUs) against renewables advocates.

Following speeches in which they noted the many economic benefits to California from renewables, the commissioners voted unanimously against the IOUs and in favor of a definition of the NEM cap that will allow for much more distributed generation (DG) going forward.

“This is a big, big win,” said Mainstream Energy Director of Government Affairs Ben Higgins.

Like 43 other states, California has a NEM program that allows owners of DG systems of up to one megawatt in capacity, like small wind turbines, combined heat and power systems and rooftop solar systems, to reduce their electricity bills.

For the kilowatt-hours they send to the grid, system owners’ meters turn backwards as they are credited at the same retail rate they pay for the kilowatt-hours they consume.

When California established its NEM program in 1995, it imposed a 0.1 percent cap but used the ambiguous language of “aggregate customer peak demand” to define what the total megawatts of net metered systems should be divided by to calculate the cap percentage. And that calculation remained undefined, even as the CPUC expanded the cap to today’s five percent.

The differing methods used by the IOUs to calculate the bottom term of the cap equation, and the differing percentages thereby obtained, were recently observed by the Interstate Renewable Energy Council (IREC) which, among its other activities, acts as a watchdog group on U.S. net metering programs. IREC filed a motion asking the CPUC for clarity. Commission President Michael Peevey issued a proposed decision April 5.

He pointed out several differences in how the IOUs calculate the percentage of their NEM but noted one key commonality: Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E) all use “coincident” peak demand. Renewables advocates argue that “non-coincident” peak demand should be used.

Coincident peak demand is the designated period when all sectors (residential, commercial and industrial) reach their maximum electricity consumption and the state’s consumption peaks.

Non-coincident peak demand is the sum of the individual peaking demands of all customers in the three sectors. Residential peak is typically late afternoon, commercial peak is early midafternoon, and industrial peak can be at night. That sum of all peaks is greater than the total peak demand at any one time of the day.

When the installed DG capacity eligible for NEM divided by the peak demand gets to five percent, the utilities are off the hook. So they want that bottom number to be smaller. Renewables advocates want just the opposite because the larger number keeps what one solar advocate called their “backbone” incentive in place.

Peevey concluded that the legislature “did not intend ‘aggregate customer peak demand’ to mean coincident peak demand…[and] SCE, SDG&E, and PG&E should use the aggregation of customers’ non-coincident peak demands to calculate their caps on NEM participation…” The commission voted 5-0 to validate Peevey's decision.

In comments filed by their attorneys, the IOUs disputed Peevey’s conclusions. PG&E’s filing complicated the basic dispute by suggesting a change in the way both numbers would be calculated and concluded, “PG&E recognizes that this means more net metering. However…[it] is the better measure of the impact on the grid…”

By raising the issue of the impact of renewables on the grid, PG&E exposed the heart of the real debate between renewables advocates and the IOUs.

The utilities pointed out that of the three parts of the standard electricity bill, only one covers the price of electricity generated. The other charges cover the costs of delivering electricity through the transmission and distribution infrastructure. When NEM customers’ bills are reduced by the retail rate, they escape paying their fair share of costs for infrastructure they use as much as non-NEM customers. And, the utilities argued, it shifts costs to other ratepayers.

But the difference between the generation cost and the full retail cost of electricity is not necessarily a subsidy if the cost shifted to other ratepayers pays for benefits to them as well.

Consulting firm Crossborder Energy principal Tom Beach did a thorough cost-benefit analysis that was based on PG&E data and included a review of two previous cost-benefit analyses. It showed that if the higher value of the power not consumed due to the use of DG is considered, the benefits to the utility are greater and the costs to the other ratepayers are offset.

The biggest component of the benefit, Beach said, is the savings on power plant use and fossil fuel use. Such energy and capacity savings, Beach said, comprise 60 to 70 percent of the benefit to all ratepayers from the rooftop solar facilitated by NEM. And, Beach added, transmission and distribution system savings avoid the costs of line losses and the need for new transmission that provide another ten percent to twenty percent of the benefits from NEM.

Beach’s calculations came to a net benefit from NEM of two cents per kilowatt-hour for commercial and industrial systems, a cost of two cents per kilowatt-hour for residential systems, and, in sum, no cost extra cost of any significance to ratepayers.

MiaSolé Sets Efficiency Record for Solar on Flexible Substrate, Plus Recent PV Highs

2012-05-24T15:55:01+00:00

We've been keeping a tally of recent record-setting solar cell and module achievements.

We're now adding MiaSolé's 15.5 percent efficiency mark for a flexible CIGS solar cell. Note that this is an aperture-area efficiency on a commercial-size flexible PV module with a total area of 1.68 square meters. That eclipses the 13.4 percent mark recently set by SoloPower. MiaSolé is targeting commercial deliveries of 14-percent-efficient glass modules by the end of the year.

MiaSolé placed third in CIGS panel production in 2011, behind Solar Frontier (at 400 megawatts) and Solibro (at 66 megawatts), according to GTM Research. The firm also recently announced a 17.3-percent-efficient champion device, while the "manufacturing process for 14 percent efficiency is now in production." The firm recently made a rare presentation in Palo Alto, California to the Silicon Valley IEEE PV Chapter.

Some of the following milestones represent 'hero experiments,' but nevertheless -- the numbers keep rising. Here are some recent announcements of record-setting results:

Heliatek set a record for organic solar cells. It's a champion cell on a small area, but it has achieved 10.7 percent efficiency. The efficiency value for the 10.7 percent champion cell would be about 9.0 percent when deposited on a flexible substrate. The question remains: can organic solar cell technology be successfully commercialized in an unforgiving solar market dominated by crystalline silicon and First Solar? Back in late 2009, Heliatek raised $27 million to build its first factory from venture capital investors Wellington Partners, RWE Innogy Ventures, and BASF Venture Capital, as well as industrial giant Bosch.

SoloPower now boasts an NREL-measured aperture area efficiency of 13.4 percent. Module efficiency is significantly less than that. The value proposition for flexible modules from SoloPower and others is that there is less hardware required to install and the installation is easier. This thesis has yet to be proven in volume and scale. SoloPower builds flexible solar panels in a roll-to-roll electroplating process.

Suntech's (NYSE: STP) Pluto cell technology achieved a 20.3 percent efficiency for a production cell using commercial-grade p-type silicon wafers. Pluto technology is a combination of different elements which are brought together to improve cell efficiency, with 21 percent efficiency targeted within the next year. These incremental improvements include surface patterning, improved metallization, improved front metal contact dimensions, changes in dopant concentration at the emitter, and improved high-temperature performance. None of these processes come cheap. Plus, the new product has not exactly replaced Suntech's existing lines -- it appears to remain a premium product that is offered at premium prices.

Solar Frontier is number two in thin-film solar and number one in the CIGS/CIS race, with 400 megawatts shipped in 2011. The firm just racked up a 17.8 percent aperture-area efficiency on a 30-centimeter-square CIS-based PV lab module. The result was claimed to come on a "fully integrated submodule" performed with processes "very similar to what is in place" in Solar Frontier's factories at commercial production scale, according to a release from the firm. The Japanese firm's Kunitomi factory recently built a champion module at 14.5 percent aperture efficiency, equivalent to a 13.3 percent module efficiency.

First Solar (NASDAQ: FSLR) hit a new world record for CdTe PV module efficiency with a 14.4 percent total area efficiency in January. That mark comes six months after First Solar hit a CdTe solar cell efficiency of 17.3 percent. Both records were set at the firm's Perrysburg, Ohio factory.

Alta Devices' most recent gallium arsenide (GaAs)-based solar panel boasts a 23.5 percent efficiency, as verified by the National Renewable Energy Laboratory (NREL). The firm claims that "this is the highest solar panel efficiency yet achieved." The press release did not discuss the size of the panel and the company has not yet responded to our inquiry.

Alta Devices has won more than $120 million in venture funding from August Capital, Kleiner Perkins Caufield and Byers, Crosslink Capital, DAG Ventures, NEA, Presidio Ventures, Technology Partners, Dow Chemical, AIMCo, Good Energies, Energy Technology Ventures, and Constellation Energy. The firm is still in the pilot manufacturing phase. Chris Norris, the CEO of Alta, has said that the company's goal is to "compete with fossil fuels without government subsidies" and get to a levelized cost of energy of $0.06 to $0.07 per kilowatt-hour. The epitaxial lift-off technique pioneered by Alta founder Eli Yablonovitch allows the firm to produce layers of GaAs that are flexible and measure only one micron in thickness.

SunPower has been the heavyweight champion of the world when it comes to commercialized cell and module efficiencies for the last half-decade -- and by a significant measure. The company's back-contact crystalline silicon cell design, in commercial production since 2005, moves the metal contacts to the back of the wafer, maximizes the working cell area, and eliminates redundant wires. SunPower has been able to achieve consistent improvements in efficiency with each successive generation of commercialized cells, and this has translated to gains in the module arena, as well. The firm's Gen 3 cells have efficiencies in excess of 23 percent.

Solar Junction, a developer of multi-junction cells for high-concentration photovoltaic (HCPV) applications, is working with Semprius and has inked an agreement to deliver multi-megawatts of epitaxial wafers. Semprius recorded a module efficiency of 33.9 percent.

Abound Solar, a manufacturer of cadmium telluride PV modules, announced the production of 82.8-watt modules at its Longmont, Colorado factory, representing a 12.2 percent aperture efficiency that is now being verified by NREL. The units were produced on "existing production equipment," according to the firm's press release. Abound claims to have produced its millionth module in December 2011.

BrightSource: The Rumors of Concentrating Solar Power’s Demise Are Wrong

2012-05-24T15:00:52+00:00

The seemingly endless stream of cars coming out of BrightSource Energy’s 370-megawatt Ivanpah solar power plant complex bolsters the company’s recent declarations about its growth and the progress of the U.S. concentrating solar power (CSP) sector.

“We’ve got 1,700 [people] at work,” said BrightSource Vice President for Government Affairs and Communications Joe Desmond. He added, many are from California’s Inland Empire, where unemployment reached 15 percent at the height of the Great Recession. “These are family-wage jobs. They’re electricians, pipefitters, welders, heavy equipment operators, engineers and biologists.” There is also a helmets-to-hardhats program designed for veterans.

“People talk about the CSP industry being dormant or paused,” explained BrightSource Communications Director Keely Wachs. “Last year, PV had a banner year. The industry installed 868 megawatts in the U.S.,” said Wachs. “Now, there are 1,200 megawatts of CSP under construction in the U.S. alone, which will mean a 120 percent increase by 2013 over the 530 megawatts of operational CSP in the U.S. today.” And that, he added, “is not including the 3,000-plus megawatts under development.”

Competitors SolarReserve (which has projects under way in Nevada and California) and Abengoa (which is developing in Arizona) would agree. But BrightSource is the biggest. A 29-megawatt plant is on-line, doing enhanced oil recovery (EOR) for Chevron. The three-tower, 370-megawatt Ivanpah project, in Ivanpah, CA, near Las Vegas, is on schedule to go on-line in 2013. And both its three-tower, 500-megawatt Hidden Hills project and its three-tower, 750-megawatt Rio Mesa project are under permitting review by the California Energy Commission, with decisions expected by the middle of 2013.

Altogether, BrightSource expects to have thirteen plants, totaling 2,377 megawatts of capacity, on-line by 2017.

The BrightSource solar power tower technology was developed by the builders of the original CSP trough technology at the nine Solar Energy Generating Stations (SEGS) still in operation today -- and not far from Ivanpah.

“We produce high-temperature, high-pressure steam to turn a turbine,” Desmond explained. And, where it is contracted for, “we transfer heat from the solar field through a heat exchanger to molten salt for storage.” The technology is sophisticated enough that multinational engineering giant Bechtel was brought on at Ivanpah for engineering, procurement and construction (EPC) duties.

The Ivanpah facility without storage, said Desmond, has a 32 percent capacity factor. “A PV panel might have a 21 percent capacity factor,” Desmond went on. “If we add between two and six hours of storage, the capacity factor will be above 50 percent.” More importantly, Desmond added, “when you increase the capacity factor, you’re not necessarily increasing your cost at the same rate. You’re taking your fixed costs and spreading them out over more hours, which helps drive down cost.”

BrightSource is concerned about costs. To minimize transport expense, it has built a heliostat assembly plant at the Ivanpah facility where a union workforce turns flat mirrors into heliostats at the rate of 500 per day.

Moving to air cooling also promises cost savings. With trough technology, he explained, “there was a preference not to go to dry cooling because there was an efficiency loss.” But the tower operates “at a higher temperature and pressure that allows us to offset some of that efficiency change.”

“That is the conversion of thermal energy to electricity -- photon to electron -- efficiency,” Wachs added. “The troughs were about 36 percent. Ivanpah is 42 percent with air cooling. Hidden Hills goes up to almost 44 percent. And when you get to supercritical levels, you get to 46 percent. Like a super-efficient coal plant. That is where we are headed, because of our heliostat design and our ability to understand the sun.”

Water use is also minimized, Wachs added, because the entire system is a closed loop. The steam is condensed to water and recirculated. “We don’t require external water for cooling purposes.”

BrightSource engineers are using on-the-ground experience to find new design efficiencies. “As we go from one project to the next,” Desmond said, “we are figuring out how to do it faster, better, and cheaper. We see that already at Ivanpah. We are ahead of schedule on unit three based on what we’ve learned with work done so far on units one and two.”

A better understanding of the plant’s power block has produced a new design for the Hidden Hills project that, Desmond said, is expected to cost 40 percent more but double the output. Overall, he added, Hidden Hills is projected to be 20 percent less expensive to build.

“This is our roadmap for driving down costs,” Desmond said. “When the original SEGS plants were built here in California 25 years ago, from the construction of the first to the ninth plant, the costs came down 50 percent. Our long-term goal is a 50 percent cost reduction from where we are now. That is different from PV. They have already had an opportunity to achieve the volumes that have led to their cost reduction.”

Sadoway’s MIT Liquid Metal Battery Startup Adds $15M and Khosla Ventures as Investor

2012-05-24T14:30:25+00:00

Image Credit: photograph by Eric Schmiedl

It's almost a cliche that the missing piece of a renewable energy future is low-cost energy storage.

"Until we find a technology that is low-cost, highly scalable, and long-lasting, ubiquitous grid storage won't be possible. The all-liquid battery's elegant materials design and simple assembly process makes it the best chemical option we've seen for storing the grid at massive scale."

That's Khosla Ventures partner Andrew Chung's comment on Liquid Metal Battery Corporation (LMBC). He's now on the board of the firm; he funded founder Don Sadoway's research at MIT before the firm won the top ARPA-E award back in 2009.

LMBC just announced that it raised an additional $15 million in funding in its Round B from Khosla Ventures, Bill Gates and energy company Total.

We spoke with Phil Giudice, the CEO of LMBC, as well. He said, "Our Liquid Metal Battery technology is tremendously exciting because it has the potential to dramatically change the electric power system everywhere," in a release. The CEO told GTM that the company had passed the R&D stage and was moving into commercializing the technology for large-scale grid applications.

The inventor of the core technology for the battery is Don Sadoway, MIT Professor of Materials Chemistry, one of MIT's most popular professors and sought-after speakers. Sadoway has challenged the research community to invent a colossal yet cheap battery. He directed researchers to look at the economy of scale of modern electrometallurgy and the aluminum smelter, which handles the holy grail of batteries: achieving a high current while maintaining massive scale.

Why is an aluminum cell not a battery? You have to produce liquid metals at both electrodes.

Making metal at the cathode is trivial, but making metal at the anode is not so trivial. So Sadoway went back to the periodic table and used magnesium to "intimidate" antimony into behaving like a non-metal. From there, using seed money from within MIT, Sadoway and his team invented the liquid metal battery or, more academically, a process called Reversible Ambipolar Electrolysis.

The battery uses molten antimony and molten magnesium separated by an electrolyte. Sadoway claims that the all-liquid configuration is self-assembling and is expected to be scalable at low cost. Furthermore, this technology may have a shot at being cheaper than sodium sulfur (NaS) batteries.

Sadoway has spoken about how rechargeables have improved as we progressed from lead acid at 35 Wh/kg to Li-ion at 150 Wh/kg (versus gasoline at 12,000 Wh/kg). But Sadoway doesn't think that Li-ion batteries have a future in grid-scale or transportation applications. We need to change chemistries and that takes radical innovation, according to Sadoway, in order to make solar and wind power more dispatchable. In this case, we need to make a battery that can handle high current.

Lithium-ion batteries in phones and cars have to be ultra-safe. Cell phones "need to be idiot-proof, largely because they are in the hands of idiots," and batteries in cars need to be able to withstand a crash. Stationary batteries for bulk storage are not held to those same requirements, which allows more freedom in choice of chemistry, but the application requires a very low price point -- and Sadoway insists that you have to think about price point at the beginning of the product design process.

It's no secret that Vinod Khosla is not a big fan of lithium-ion batteries.

Automotive traction for an all-electric car has a target cost of $100 to $200 per kWh, and stationary storage needs to be in the vicinity of $50 per kWh, according to Sadoway.

Sadoway has weighed in on the woeful state of energy research in the U.S., saying, "We need to accelerate the rate of discovery. We can make batteries two or three times better if we're willing to make the investment." He said that energy research has fallen by a factor of six, while medical research has grown by a factor of four since the 1970s. He also observes that the U.S. energy industry spends 0.25 percent of revenues on R&D, while the pharmaceuticals industry spends 18 percent and semiconductor firms spend 16 percent. Even the automotive industry spends 3 percent of its revenues on R&D.

Sadoway recommends that researchers "confine their search to earth-abundant elements. The only way to make something dirt cheap is to make it out of dirt -- American dirt."

Though revolutionary technology is a good thing, getting storage on the grid is going to involve leveraging technology, price, and, just as importantly, regulatory issues involving the FERC, and ISOs and PUCs across the nation.

Building the Smart Grid Network That Grows

2012-05-24T14:00:53+00:00

Trees are a growing problem with smart grid networks. Every day, they stretch toward the sun, expand, droop, lean, and sometimes fall down, changing the physical environment in which wireless networks operate. In some cases, if uncorrected, they can cause network failure.

The usual way to fix that is to put in another base station or concentrator, at additional cost. That’s because routing the network around changes in its environment is complicated, both to plan and then to deploy -- and once you’ve deployed, the trees have gone and grown and fallen again, wrecking your model.

That’s how Andres Carvallo, chief strategy officer at Proximetry, described the problem he’s hoping a new partnership with EDX Wireless will solve.

In simple terms, Eugene, Ore.-based EDX makes the tools to plan networks, and Proximetry makes the tools to manage them, Carvallo said in a Tuesday interview. The San Diego, Calif.-based startup’s software runs on its own, or via licensing partners like Cisco, which uses it for its smart grid network management offering, or CSC Corp. for a cloud-based network management service for utilities.

From there, Proximetry feeds all that data back into the EDX planning process, where it goes into a new cycle of modeling, he said. That keeps engineering and operations updated with fresh tools to make plans, fix problems, and catch the slow degradation of performance that would otherwise manifest in failure and expensive upgrades.

Carvallo saw the problems that neighborhood networks can experience firsthand during his stint as CIO of municipal utility Austin Energy, where crews trim some 400 linear miles of power line corridors per year, mostly to prevent branches from touching power lines and starting fires.

But it turns out that leafy green residential neighborhoods make for poor wireless connectivity as well. At Austin Energy, Carvallo estimated that up to 15 percent of network devices -- smart meters -- experienced failure at one point or another due to such changes as vegetation growth, new construction, public works projects and other environmental changes.

“Today, it’s all manual troubleshooting” to fix the problem, he said. “You have to send people there to figure it out.” Proximetry can optimize networks in a way that avoids having to reinforce troublesome networks with personal inspections and new gear, to the tune of 30 percent to 40 percent reductions in those network maintenance costs, he said. The software can also detect imminent failure for preventative maintenance, or notice when gear is running just fine and doesn't need to be replaced on a schedule, all for additional savings and operations benefits.

Proximetry isn’t alone in offering smart grid network management of some kind, of course. Telcordia, now owned by Ericsson, has a smart grid NMS offering. Another contender is GridMaven, a business unit of SK Telecom’s American subsidiary that launched in January, the same day as Cisco announced its Proximetry-backed network management system. This week, GridMaven announced it had finished deploying the network management system for South Korea’s Jeju Island, a national smart grid test bed that’s one of the biggest single deployments in the world.

But for now, GridMaven has said it is sticking to network fault detection and correction, rather than automation of network responses. Proximetry, on the other hand, is looking at increased automation with EDX, in terms of constantly updating the models that utilities use to plan and execute their projects.

“There’s got to be a closed loop, iterative cycle of design, planning operations, optimization, design, and so on and so on,” Carvallo said. Otherwise, every new project needs a team of engineers to solve all the new problems, he said.

Just how Proximetry’s technology compares to the likely contestants in the field of winning utility business remains to be seen. The big cellular carriers have their own network optimization underway to support the smart grid’s particular needs, for example. Smart grid services offerings from the likes of General Electric, SAIC and Lockheed Martin presumably have some way to tie their views together.

Proximetry was founded in 2005 and has been backed by Munich Venture Partners, Aeris Capital, Investec, and Rembrandt Venture Partners. It raised a $5 million Round A in 2007 and in June raised $792,000 of a planned $1.08 million round, according to a regulatory filing. It has also won grants from European government entities (PDF), and has offices in Poland and Germany.

What to Make of Geothermal’s Numbers

2012-05-24T10:00:00+00:00

The Geothermal Energy Association’s newest report on global growth is an admirable effort on putting on a happy face -- but its numbers tell another story.

The association reports, for instance, that in 2010 geothermal energy generated “twice the amount of electricity as solar energy did worldwide.” The world’s installed grid-connected PV capacity went from 7.4 gigawatts at the end of 2009, to 16.8 gigawatts at the end of 2010, to 29.7 gigawatts of grid-connected PV at the end of 2011.

The world’s installed geothermal capacity, as of May 2012, was 11,224 megawatts (11.2 gigawatts), up from 10.7 gigawatts of installed capacity in 2009 (according to the IEA). It would appear geothermal did have the lead sometime in 2010, but comparing the sectors' growth rates is not flattering to geothermal. (Geothermal obviously has an advantage when it comes to generating kilowatt-hours due to its higher capacity factor.)

The telling measure is geothermal’s U.S. performance. According to the GEA report, utility-scale geothermal originated in the U.S. in the 1960s. The U.S. “remains the world leader with approximately 3,187 megawatts of installed capacity,” but the GEA reported it brought only “approximately 91 megawatts of capacity on-line between 2011 and early 2012.”

That’s far less than the 1,855 megawatts of photovoltaics deployed in the U.S. in 2011.

The U.S. wind industry added 6,816 megawatts (6.8 gigawatts) of new capacity in 2011, a 30 percent increase over the previous year’s growth.

There is, however, cause for optimism in the geothermal industry. While GEA President Karl Gawell noted that “growth in the United States is still hindered by uncertainty about the direction of government policy” (an observation echoed by leaders in the solar, wind and natural gas sectors in 2012), the rest of the world plans to seize the geothermal opportunity.

The Turkey Geothermal Association estimates, according to GEA, that its industry will grow from 100 megawatts of installed capacity to 500 megawatts by 2015. Kenya, with 202 megawatts of installed capacity, is developing fourteen new sites. And Indonesia, which is situated on the famed ring of fire and is estimated to have 27,510 megawatts of geothermal potential, intends to build its installed capacity to 5,000 megawatts by 2025.

A recent GTM interview with EnergySource President and CEO Dave Watson, who just commissioned the 49-megawatt Hudson Ranch I project in California’s potential-rich Salton Sea known geothermal resource area (KGRA) and is already readying a matching 49-megawatt Hudson Ranch II project, offered insight into the GEA’s positive attitude.

“At some point,” Watson said of grid operators now buying up solar and wind contracts, “they’re going to want some grid stability [and] we’re running twenty-four hours a day. When the utilities get tired of dealing with intermittency and want baseload renewables, there’s really only one source -- and that’s geothermal."

Smart Grid Market in China, Japan and South Korea to Hit $19 Billion by 2016

2012-05-23T19:00:11+00:00

Asia is quickly becoming a center of global smart grid activity. The cumulative smart grid market in China, Japan and South Korea is currently valued at $8.5 billion, with that number forecasted to increase to $19 billion by 2016, according to GTM Research's latest market report, The Smart Grid in Asia, 2012-2016: Markets, Technologies and Strategies.

At over 180 pages, The Smart Grid in Asia, 2012-2016 is the definitive source for organizations looking to capitalize on Asia's predominant smart grid markets. A clear understanding of the energy scenarios in China, Japan, and South Korea, as well as their respective smart grid technology and deployment trends, will be crucial to achieving meaningful entry in Asia. This report provides a detailed five-year smart grid forecast, domestic vendor taxonomies, and strategic perspectives on how smart grid players should position themselves for success in each market.

"We expect to see the smart grid in Asia move forward at a breakneck pace," said Kamil Bojanczyk, the report's lead author and an analyst-at-large with GTM Research. "Over $45 billion in funding has been earmarked by governments and utilities across China, Japan and South Korea, with the clear majority of those funds and opportunities originating in the Chinese market."

FIGURE: Smart Grid Market Assessment for 2016

Source: The Smart Grid in Asia, 2012-2016 (GTM Research)

Bojanczyk indicated that each country's growth will be characterized by the specific needs of its utilities and existing grids. The vast majority of smart grid investment in China centers around transmission, distribution automation and automatic metering reading (AMR) to support a developing grid and robust renewable energy build-out.

In Japan, the sunsetting of all of the country's nuclear plants has created an acute need for demand response, home energy management and smart meter deployments.

In South Korea, the market is developing quite differently; for the country with the most reliable grid in the world, South Korea and its chaebols are looking to develop next-gen smart grid technologies across all segments, primarily for global export.

In addition, the report identifies the leading strategies for addressing each of Asia's smart grid markets, and analyzes the companies that are currently winning big. This list includes; ABB, Accenture, BPL Global, Echelon, Freescale, GE, Holley Metering, Moxa, RuggedCom, Siemens, State Grid Corporation of China, Wasion, XD Electric, and XJ Group.

For more information on this report and to download a brochure with the complete table of contents, visit http://www.greentechmedia.com/research/report/smart-grid-in-asia-2012-2016.

SunRun’s $60M Round Leads a Small Streak of Solar VC Funding

2012-05-23T18:10:32+00:00

Despite the modest results or non-performance of recent solar IPOs, the doldrums of the solar market, and the shakeout in the greentech VC world -- there's been a small recent run of solar venture capital financing worth recapping here.

First, SunRun, the San Francisco-based solar leasing company, just raised $60 million in a round led by Madrone Capital Partners, along with existing investors Accel Partners, Sequoia Capital and Foundation Capital. That brings SunRun's total VC funding to $145 million with enough capital to support the purchase of over $1 billion in solar systems. SunRun focuses on financing residential solar rooftops, one of the bright spots in the solar market, though it is a sector threatened by the recent solar tariff to be imposed by the U.S. Department of Commerce.

SolFocus, a concentrating photovoltaic (CPV) systems vendor, won $10.75 million in venture capital from NEA, Apex, NGEN, et al. according to an SEC filing. SolFocus has a project in development in Mexico that could eclipse the 30-megawatt Alamosa, Colorado CPV farm.

Gen110, a San Francisco startup with 70 employees, 11 offices in California and about 2,000 customers for its solar-backed energy bill reduction service, announced an undisclosed investment from Kleiner Perkins Caufield & Byers to expand its “energy concierge” concept to broader markets.

Solantro Semiconductor completed its $10 million round A with funding led by family fund Black Coral Capital, as well as Presidio Ventures (a Sumitomo Corporation company), Business Development Bank of Canada (BDC) and Export Development Canada (EDC). Solantro designs and manufactures chipsets for use with distributed solar PV power conversion equipment, which would include microinverters from firms such as Enphase or SolarBridge and DC optimizers from firms such as SolarEdge or Tigo.

Is Net Energy Metering for Solar Power a Subsidy?

2012-05-23T17:30:32+00:00

Southern California Edison (SCE) Manager of Customer Self Generation Gary Barsley said that at an important recent conference for the solar industry and the utilities interested in it, the number-one topic of conversation was net energy metering (NEM), the incentive some solar advocates call “the civil rights legislation for solar.”

Utility and solar professionals asked, Barsley said, whether there is a valid way to quantify net metering’s costs and benefits and whether they total up to a subsidy for solar system owners or a good thing for all ratepayers. “The general consensus was that there isn’t a clear answer yet,” Barsley said, “but people are really interested in finding out, because solar is going to continue to grow.”

There are 43 states with NEM programs. NEM benefits solar owners by allowing them to roll their meters backward for every kilowatt-hour they send to the grid, up to the point where their bills zero out. The return they get on the electricity they generate is the same retail rate they pay for what they consume.

The conference chatter reflects an industry-wide concern over the future of NEM as the California Public Utilities Commission (CPUC) readies a decision, expected May 24, on the question of how to define the NEM cap. Underlying the legalism involved in the CPUC decision, as Barsley noted, is a debate between solar advocates and SCE, Pacific Gas and Electric (PG&E), and San Diego Gas and Electric (SDG&E), California’s three investor-owned utilities (IOUs).

“There is a belief that the net metering tariff, the way it is applied today, gives an additional benefit or subsidy to solar customers and the price of that subsidy gets passed on to our other non-solar-owning ratepayers,” Barsley said. “As more customers get the net metering tariff, that’s more and more costs that shift to non-solar customers.”

“The utilities haven’t provided any data on the increased costs,” said the CPUC Acting Director of the Division of Ratepayer Advocates (DRA) Joe Como, whose job is to stand up for the ratepayers the utilities are supposed to be protecting. NEM “cuts into their business and they’re not the ones getting the money,” he added. “They’re never upset when they’re receiving the money.”

The CPUC decision will be on a legal question, but sooner or later the value of NEM will also have to be decided.

Utilities are essentially arguing that of the three charges in an electricity bill -- one for power generation, another for transmission system expenses, and a third for distribution system expenses -- solar system owners should only be remunerated for the first and should have to pay for the wires they use when the sun is not shining.

But the difference between the generation cost and the full retail cost of electricity is not necessarily a subsidy if the cost that is shifted to other ratepayers pays for benefits to them as well. Only a cost-benefit analysis would show that.

“Our own rates group is trying do an evaluation,” Barsley said.

Consulting firm Crossborder Energy principal Tom Beach has done one. It included a review of two previous cost-benefit analyses, one by Lawrence Berkeley National Laboratory (LBNL) and one by the E3 consulting firm.

Both the Beach and LBNL studies, based on PG&E data, showed that if the higher value of the power not consumed by NEM customers is considered, the benefits to the utility are greater and the costs to the other ratepayers are offset.

“The biggest component of the benefit is that when someone produces power at their home or business and exports it to the grid,” Beach said, “a power plant somewhere else on the system gets turned down because that power does not have to be produced.” That provides two cost savings, he explained -- the natural gas that doesn’t get burned and, as demand grows, the power plant that doesn’t have to get built.

“The first kind of savings is called energy savings,” Beach said. “The second kind of savings is called capacity savings." Together, he added, “they’re 60 percent to 70 percent of the savings.”

There are transmission and distribution system savings as well, Beach said. “When you run the meter backwards,” he said, “you’re putting power out to the grid that, as a matter of physics, basically supplies your neighbors. It doesn’t go very far.”

That avoids a cost that provides another 10 percent to 20 percent of the benefits from NEM. “The utility does not have to generate power in a remotely located power plant and transmit that electricity over its wires,” Beach said. “A lot of power is lost in the wires and the transformers. It avoids those losses.” And, he added, “in the long run, it will mean we have to build less transmission.”

Beach’s calculations identified a benefit from NEM of two cents per kilowatt-hour for commercial and industrial systems, a cost of two cents per kilowatt-hour for residential systems, and, in sum, no cost extra cost of any significance to ratepayers.

NEM leverages private money for a public benefit, observed Como. “Most of the money being spent is going to be spent by the private sector. That creates jobs, stimulates business, promotes reductions of greenhouse gases, stabilizes energy costs, and diversifies the grid.” And, he added, “you have to be a little more visionary. Energy policy in California mandates that we are going to renewables.”

The Bad News in CPV: Amonix Layoffs and Soitec Losses

2012-05-23T17:30:21+00:00

Earlier this week, we reported on some of the positive news in the world of concentrating photovoltaics (CPV): efficiency gains, venture funding, and some decent-sized deployments.

Today we report on some bad news at CPV system vendors Amonix and Soitec.

Amonix plans to lay off 76 employees, according to a filing it made with a state agency, as reported in Dow Jones. We've reported on Amonix's world-record 30-megawatt Alamosa solar farm and the tragic loss of its CEO Brian Robertson in December of last year. The layoff notice came from a Worker Adjustment and Retraining Notification, filed by Amonix with the California Employment Development Department earlier this month.

Amonix has raised approximately $140 million in venture capital from Kleiner Perkins, Adams Street Partners, Angeleno Group, New Silk Route, PCG Clean Energy & Technology Fund, Vedanta Capital, Westly Group, and MissionPoint Capital Partners. The Alamosa CPV site is funded by a $90 million DOE loan guarantee to developer Cogentrix.

Cogentrix is a subsidiary of The Goldman Sachs Group and most of its previous projects have been for fossil fuel plants. Ben Kortlang, the KPCB partner on the Amonix board of directors, spent eight years at Goldman Sachs prior to his investment in Amonix at KP.

In a 2010 interview, the amiable Mr. Kortlang told me, "The denominator in all solar is efficiency," and Amonix is the most efficient solar system available at 25 percent AC efficiency. Kortlang concluded with the observation, "This is cheaper than First Solar."

Amonix doesn't cite a CEO on its website, and onetime interim CEO, Jan van Dokkum, a Kleiner Perkins partner, is no longer listed on the website. Vahan Garboushian, the founder, CTO, and chairman of Amonix, shepherded the firm through its earlier stage of steady organic growth.

Soitec has large CPV plants in the works, as well as over 150 megawatts of PPAs with San Diego Gas & Electric and a 50-megawatt plant in South Africa.  But the firm's solar division (gained from its acquisition of Concentrix) is bleeding cash. With a small increase of year-to-year sales, Soitec's 2011 losses have almost doubled to 44.9 million euros.

Thin Film Manufacturing in the Sub-Dollar-Per-Watt Market: Part II

2012-05-23T16:00:48+00:00

Following up on Part One of our series on thin-film PV based on GTM Research's Thin Film 2012–2016 report, we take a more incisive look at the manufacturing and competitiveness of thin film, as well as the levers suppliers can use to drive down costs.

In order to understand the competitive dynamics between crystalline silicon (c-Si) and thin-film PV, we must first look at the staple of PV market competitiveness: manufacturing costs. In the figures below, we break down the typical cost structures for a leading Chinese multicrystalline silicon PV module manufacturer and our estimates for First Solar’s Malaysia facility running at full utilization in 2012. Although overall costs are dissimilar, the cost of the multicrystalline silicon comes to about $0.82/W versus just $0.63/W for First Solar (not including stock-based compensation, warranty, and recycling). These examples serve as a benchmark for cost structure comparison of mature facilities.

FIGURE: Chinese c-Si Module vs. First Solar CdTe Module (Malaysia), 2012E

Source: Thin Film 2012-2016: Technologies, Markets, and Strategies for Survival (GTM Research)

As exhibited in the cost breakdowns, raw materials for c-Si PV amount to 72 percent of the total cost structure, with polysilicon as the single largest contributor to underlying costs. In contrast, CdTe feedstock contributes only 10 percent to the total cost structure of a CdTe panel, which underscores thin film’s limited dependency on a potentially volatile commodity metals markets. For CIGS and thin-film silicon, this cost component can be less than 10 percent of the total cost of the module. This advantage, however, can be a double-edge sword; the cost structures provide a large incentive for c-Si manufacturers to reduce silicon costs and usage, whereas thin film suppliers remain dependent on commodity material costs like glass, edge sealants, and junction boxes.

Without a dramatic lowering of raw material costs on the horizon, thin film manufacturers will have to rely on other levers to reduce costs. Efficiency is the most obvious, and improvements provide a two-fold benefit: efficiency gains reduce material costs on a per-watt basis and reduce the balance-of-systems penalty suffered by low-efficiency products.

2011 was full of record efficiency announcements, including First Solar’s CdTe record cell at 17.3 percent, Solar Frontier’s 17.8 percent cell aperture-area efficiency, and SoloPower’s flexible module aperture-area efficiency of 13.4 percent. Understandably, these announcements do not represent commercially available technologies; the actual best commercially available module efficiencies are much lower. However, the record efficiency announcements are a promising indication that high-efficiency thin film products could be available in the next few years.

FIGURE: Record vs. Average Annual Efficiencies by Technology

Source: Thin Film 2012-2016: Technologies, Markets, and Strategies for Survival (GTM Research)

But to what degree can efficiency bridge the gap between thin film and c-Si PV manufacturing costs? The answer varies depending on manufacturing process and technology, but generalizing a fully utilized reference 500-megawatt CIGS manufacturing facility based in the U.S., Europe or Japan producing a 12.5-percent-efficient CIGS module, we find that, unsurprisingly, efficiency can lead to significant savings across the cost structure. Assuming that the capex is the same and efficiency tweaks come only from minor changes in process that do not affect uptimes and yields, we isolate the effect of efficiency on CIGS module manufacturing in the following figure.

A 0.5 percent absolute gain in module efficiency (from 12.5 percent to 13.0 percent) nets a 5 percent savings in module manufacturing costs. However, the benefits decay as manufacturers push efficiencies higher. For example, while pushing from a 12.5-percent to a 14-percent efficient product saves approximately 12.1 percent in module manufacturing costs, the savings-per-percent-efficiency is only 8 percent, as opposed to the 10 percent we saw moving from 12.5 percent to 13.0 percent.

In absolute terms, a module manufacturer pushing from 12.5 percent efficiency to 14.0 percent efficiency nets a $0.10 per watt savings. GTM Research estimates that actual fully loaded costs for a leading CIGS manufacturer in 2012 could be as low as $0.89 per watt dc (note that this reflects underutilization). Thus, a $0.10 per watt dc savings could pull CIGS manufacturing costs below estimated c-Si manufacturing costs. This CIGS manufacturer would still have to sell at more than the $0.03 per watt difference (vs. our 14.5 percent, $0.82 per watt dc Chinese c-Si reference) to account for the efficiency discrepancy between CIGS and c-Si. Nevertheless, manufacturing high-efficiency thin film is a key factor toward competitiveness, especially at the lower end of the efficiency spectrum.

FIGURE: CIGS Costs vs. Efficiency for 500-Megawatt Plant in Europe/North America/Japan

Source: Thin Film 2012-2016: Technologies, Markets, and Strategies for Survival (GTM Research)

Yet efficiency isn’t the only lever for thin film manufacturers to capitalize on to triumph over c-Si PV. Other levers available to thin film manufacturers include process yields, throughput/uptime, and the always-important scale. According to a 2009 publication by the Boston Consulting Group study, quadrupling scale from 100 megawatts to 400 megawatts can create a 15 percent to 25 percent, 20 percent to 30 percent, and <10 percent drop in production costs in c-Si wafer, cell, and module costs, respectively. These reduction estimates don’t necessarily translate to thin film, but they do provide a basis for the range of scale improvements that can be expected from module manufacturing, regardless of technology. Based on industry channel checks, we model an upper limit of 10 percent decreases in cost for the doubling of production capacity, which means that the benefits of scale begin to peter out after the one- to two-gigawatt mark. Given that 90 percent of thin film facilities are smaller than 250 megawatts, thin film manufacturing still has a lot of room to grow -- if (and that’s a big 'if') the demand market and current oversupply environment has room for it.

FIGURE: Thin Film Facilities by Production Capacity, Year-End 2011

Source: Thin Film 2012-2016: Technologies, Markets, and Strategies for Survival (GTM Research)

To that last point, blind expansion is not a wise move in the current environment. Even with industry-leading costs and a strong captive pipeline to absorb demand, First Solar still expects utilization rates could drop to 85 percent on the year. While that’s not to say other thin film manufacturers won’t find a secret sauce unobtained by First Solar (e.g., access to significant Chinese or Japanese downstream pipeline), it does call into question announcements by thin film manufacturers like Hanergy that targeting gigawatts of production capacity by year's end (but in fairness, we were skeptical about Solar Frontier's desire to immediately scale from just 80 megawatts to 980 megawatts, too). Growing too quickly will result in significant underutilization, which greatly affects the fully loaded costs (i.e., costs including depreciation) of PV modules.

Whereas depreciation of c-Si capital equipment amounts to only 6 percent to 10 percent of module costs, it can account for a quarter of even a fully utilized thin film manufacturer’s costs. A large supply chain of commodity manufacturing equipment for c-Si has allowed equipment costs to come down dramatically. With current global producible capacity of c-Si PV modules above 31 gigawatts, utilization rates have fallen dramatically. However, the actual effect of low utilization on costs is limited by the relatively low capex for c-Si manufacturing. Contrast this to thin film manufacturing, where capex can easily approach and even exceed $1 per watt. Only industry-leading capex for capital equipment (minus building and facility upgrades) brush against multicrystalline silicon capex costs. While demand markets are still sorting themselves out, expansion of scale to reduce costs may only increase cash burn while crystalline competitors continue to push product at razor-thin and even negative margins.

FIGURE: Capex Costs' Effect on Module Costs, 2012

Source: Thin Film 2012-2016: Technologies, Markets, and Strategies for Survival (GTM Research)

Looking at thin film cost structures, the road for thin film competitiveness continues to be an uphill struggle. However, in the next and final part of this series, we will explore how changing market dynamics and a maturing understanding of thin film performance will ultimately drive thin film competitiveness and the long-term success of leading players.

Enter the Dragon: China and the World’s Greatest Smart Grid Opportunity

2012-05-23T15:00:50+00:00

Image Credit: Associated Press (AP)

Last week, GTM Research released its latest smart grid report, The Smart Grid in Asia, 2012-2016: Markets, Technologies and Strategies. This article is the first in a series of perspectives from the report's author on the tremendous smart grid opportunity in Asia.

In 2009, China embarked on a three-stage journey to become a world leader in smart grid technologies with its aptly named "Strong and Smart Grid" 11-year plan. The plan encompasses all aspects of the grid, including increasing generation and transmission capacity, a nationwide smart meter deployment, large-scale renewable energy integration, and a large substation build-out. Four years later, State Grid Corporation of China, the largest utility in the world and the brains behind China's smart grid plans, is in full swing with phase two of its ambitious smart grid deployment plans -- the Construction Phase, running from 2011 to 2015.

New transmission lines are a major focus for State Grid in the Construction Phase, which is struggling to meet the growing energy demands of the rising middle class in the East and South. Most coal, hydro, wind, and solar load sources are over 1,000 kilometers away from the populous east and south. High voltage (HV, under 300 kilovolts), extra-high voltage (EHV, 300 kilovolts to 765 kilovolts), and ultra-high voltage (UHV, 765 kilovolts and up) lines are being installed currently, with at least one 1,000-kilovolt UHV AC or DC line installed annually until 2015. Overall transmission line investments for 2015 are approximately $269 billion, equivalent to the combined market cap of ABB, GE, and Schneider Electric as of May 21, 2012. China is adding so much new transmission capacity and so many power lines that it could build three quarters the length of a new American transmission grid in just five years. When the dust settles, there will be over 200,000 kilometers of new 330-kilovolts-and-up transmission lines built, for a total of 900,000 kilometers of transmission lines, compared to 257,500 kilometers of transmission lines presently in the U.S.

Figure: Current and Future Transmission Line Length in China

At a cost of $1.05 million per mile for UHV transmission line and equipment, each UHV line requires billions of dollars to build, and State Grid put in a staggering $80 billion investment into 40,000 kilometer of UHV lines for the 2011 to 2015 Construction Phase. The business case is readily apparent: a 2,000-kilometer, 800-kilovolt UHV DC line has an incredibly low 3.5 percent line loss rate per 1,000 kilometer and a high 6.4-gigawatt transmission capacity, all the while being 30 percent cheaper than a 500-kilovolt EHV DC or 800-kilovolt UHV AC line of the same length. By 2020, UHV lines will have 300 gigawatts of transmission capacity, roughly split 60 percent AC and 40 percent DC.

The competitive business environment seen in the transmission grid build-out is indicative of the rest of the smart grid market in China -- high-quality goods, competitive costs, and a well-built relationship with State Grid all go a long way toward winning a contract. Fierce vendor competition exists, due in part to State Grid’s competitive construction procurement process. All projects costing over $300,000 to build are required to go through an open bidding process that aims to enforce fairness and transparency, but State Grid still holds the reigns tightly on choosing project developers. In the process, State Grid has the final say and does a rough 45/45/10 split when evaluating meters, based on quality, cost, and bankability of the company.

With the promise of power shortages disappearing and a stable energy supply base, the build-out of the transmission grid is ushering in the next era of smart grid opportunities in China. Smart meters and renewable integration are already big businesses, and new substation infrastructure has brought with it a vibrant and growing substation automation market. The need for better monitoring equipment has risen as China is keen on decreasing its system average interruption duration index (SAIDI) and improving power quality to its customers. State Grid has earmarked over $40 billion toward these smart grid technologies between 2011 and 2016, with smart meters alone being a $2.5 billion to $3 billion annual market.

State Grid has paid special attention to substation automation technologies, and plans on installing 74 new digital substations for 63 kilovolts to 500 kilovolts by 2015. While this number is small compared to the existing 40,000+ substation base, State Grid has stated it intends to include digital technology in all new substations built. Companies such as BPL Global have been expanding their substation operations in China, which has been met with stiff domestic competition. The substation market offers promising growth over the next ten years.

Figure: Digital Substation Investments From 2011 to 2015

The transmission grid build-out also has an impact on technologies at the distribution level and downward. China is building 36 million new urban homes between 2011 and 2015, and modern building automation and smart meter technologies will be utilized. The coming years promise to create a new and vibrant building automation market, but for the time being, the market continues to focus on meeting demand shortfalls and other key infrastructure challenges. Expect to see an exciting shift toward technologies at the distribution level and downward in the next five to ten years, as China’s grid solidifies its transmission grid and generation sources. If the past three years have been any indication of future progress, expect to see China become a leading smart grid market for the next five to ten years. The distribution grid build-out and digitization will be the next major indicator of China’s smart grid prowess.

For more information on China's grid build-out and The Smart Grid in Asia, 2012-2016: Markets, Technologies and Strategies, visit www.greentechmedia.com/research/report/smart-grid-in-asia-2012-2016.

How Companies Are Learning to Utilize Data

2012-05-23T15:00:03+00:00

"Data science -- that's now a field that's exponentially increased. [...] We're in this learning mode." What does the data science field mean for utilities and vendors? According to Domenic Armano from Johnson Controls, we're soon going to find out.

SoloPower Raises More Funding for Flexible CIGS Solar Panels

2012-05-23T10:00:24+00:00

SoloPower, a San Jose, California-based maker of CIGS-based flexible thin-film solar modules, just raised a small amount of venture funding, according to this SEC filing (and verified with one of the investors).

SoloPower raised $7.1 million from existing investors which include Hudson Clean Energy Partners, Crosslink Capital, Convexa, and Firsthand. The solar startup is also the recipient of a $197 million DOE loan guarantee issued in August of last year for its new Oregon factory. Corporate greentech recipients of DOE loans in the manufacturing sector such as Solyndra, Abound Solar, Fisker Automotive, and Beacon Power have met their share of challenges, though Tesla Motors, also a DOE loan recipient, might buck that trend.

Earlier this year, SoloPower raised the bar a little higher on the efficiency of its flexible solar panels, and is now boasting an NREL-measured aperture-area efficiency of 13.4 percent. Module efficiency for the firm's SF1 panel is 11.4 percent, according to Tim Harris, the CEO. The SF1 panel is optimized for metal roofs and has a junction box that is located on the front of the panel. The firm's panels are built with a roll-to-roll electrodeposition process.

SoloPower's 400-megawatt manufacturing facility in Portland, Oregon has commercial production slated for later this year.

SoloPower also recently announced that General Wesley K. Clark (U.S., retired), former NATO Supreme Allied Commander of Europe and former U.S. presidential candidate, joined SoloPower’s Board of Directors. Clark is co-chairman of Growth Energy, an ethanol lobbying organization and a board director of BNK Petroleum, a shale gas developer and producer.

SoloPower would appear to be going after the same rooftop market as Ascent Solar, Global Solar, and the now-bankrupt ECD, except it is doing it with a more efficient product. The value proposition for flexible modules from SoloPower is that there is less hardware required to install the modules and the installation is easier and less expensive. However, this thesis has yet to be proven in volume and scale.

The company claims that lighter weight makes installation easier and reduces the cost of balance-of-system components. Certainly, it can eliminate the cost of racking, which adds about $0.25 per watt.

But why bother messing with flexible CIGS designs when the price of conventional crystalline silicon continues to plummet along with the costs of balance-of-system components? And does lighter weight really provide any value?

One of the expensive parts of building a flexible CIGS module is the necessity and cost of an advanced encapsulant to protect the module and keep water out. That component remains a precipitously high-cost piece of the flexible CIGS puzzle.

I interviewed personnel at the firm last year; the CEO told me that capex is "way under a dollar [per watt]" and production cost is "competitive."

Here's the list of successful, profitable flexible rooftop solar companies:

Leafully Wins Green Button Apps Contest

2012-05-22T20:28:58+00:00

If you were to ask 100 people to define a kilowatt-hour, you'd probably get some blank stares and a few interesting answers. If you asked 100 people to define a tree, you would get slightly varying answers, but essentially the same answer.

That is the idea behind Leafully, which just walked away with the grand prize and $30,000 from the U.S. Department of Energy's Apps for Energy contest.

The app links with your Facebook profile and gives energy usage in terms of trees, which is a more meaningful term to the average person than a kilowatt-hour. It also offers an overview of energy usage, trends, a calculator and ways to save.

Leafully, like many other apps, looks at baseload power, which it calls “sleeping energy,” as well as peak power. The app translates energy use into number of trees saved, but studies have shown that only a portion of the population is motivated by environmental concerns when it comes to energy savings.

Even if the winner focused on trees instead of dollars, the power of apps overall should not be underestimated, according to Todd Park, U.S. chief technology officer. He told the utilities present at ConnectivityWeek 2012 in Santa Clara, Calif. to “embrace the power of the crowd” for more rapid innovation.

The Green Button, which was announced last fall, is a feature that allows residential and commercial customers to download detailed energy-use information in a standardized format to better manage electricity consumption and cost. Approximately 30 million utility customers will have access to Green Button data by the end of this year.

More than 50 apps competed for the prizes, covering everything from assessing rooftop solar PV for your home to small business energy management applications.

The second place prize of $15,000 went to Melon Power, which was the only company to leverage Green Button data to make it easy for commercial buildings to get an Energy Star benchmark score, a process that is mandatory in various cities and states.

“We were wowed and very impressed,” by Melon Power's app, said Karen Austin, chief information officer and senior vice president at Pacific Gas & Electric, which was one of the sponsors of the contest. “The dozens of apps we received through the contest are just what our customers are asking for: automation, self-service and mobility when it comes to helping manage their energy.”

Third prize went to VELObill, which allows customers to view their utility usage and measure whether it is high or low compared to peers and to find ways to save money. An app that simply makes the utility bill itself more understandable is badly needed, especially when you consider that most bills don't even explain their terms.

The student winners came from University of California, Irvine with the Wotz application, which uses a landscape picture to show baseload and regular energy use. It breaks this data down into everything from MacBook Air charges to cheeseburgers, and also has challenges, including a Tetris-inspired game.

In a separate contest, Benchmarx won the Biggest Energy Saver Apps Developer contest, which was sponsored by Oncor, CenterPoint Energy, Grid21, Landis+Gyr, Itron, GE, IBM and Tendril.

Benchmarx's original application was for the commercial sector, to help companies understand energy use and comply with benchmarking. The company tailored its software for the residential experience and won $50,000 in the contest.

Although the bulk of the apps' functionality aren't new to people who work in the smart grid space, they will be novel to the masses. “It's one thing to say consumers have the access, but it's more powerful for a customer to empower third parties,” said Larsh Johnson, CTO of eMeter (now part of Siemens), which supports Green Button but was not involved in the apps contest. “It will be very novel to consumers who haven't thought about it. Consumers are going to be able to have choices.”

ES-Select: Match.com for Renewable Developers and Energy Storage

2012-05-22T17:30:17+00:00

It is a measure of the Obama administration’s commitment to advancing energy storage technology that reporters in the White House press corps have taken to moaning about having to visit yet another battery factory with the President.

A better measure of the administration’s commitment is that ARRA provided $185 million for 533 megawatts of energy storage demonstration projects, including three large battery systems for wind storage totaling 53 megawatts, two compressed air projects totaling 450 megawatts, a twenty-megawatt frequency regulation project, five distributed projects totaling nine megawatts and five technology development projects.

Pike Research predicted that energy storage will move from its 2011 installed capacity of 121 megawatts to 2,353 megawatts of installed capacity in 2021.

To further this effort, the U.S. Department of Energy (DOE) has partnered with the Energy Storage Systems program at its Sandia National Laboratory to create a series of tools to help stakeholders in the renewables community better understand how they can choose and use storage technologies.

“One is the Energy Storage Handbook,” explained DOE Energy Storage Research Program Manager Imre Gyuk. “It will have everything you ever wanted to know about storage in it.”

Another tool they are developing, Gyuk said, “is a handbook for PUCs, because sooner or later storage will come before public utility commissions and, having no experience with this technology, they will be baffled. Is this load? Is it generation? Or is it transmission? We are going to do a primer for regulators and public utility commissions.”

The third tool is ES-Select. “We have been involved in the development of energy storage technology,” Gyuk said. “And we have also done analysis of cost-effectiveness, [such as] how can you actually evaluate energy storage.”

ES-Select, which is free on the Sandia website, “allows people to do a first cut of whether storage would fit their particular application and also whether they can mix together applications,” Gyuk explained.

There is, he said, “a spectrum of applications and a portfolio of technologies. Not all technologies are good for all applications. Some of the applications can double up and therefore give you a bigger return on your investment.” For example, he said, “can you use it for frequency regulation and peak shaving at the same time? Because in order to make it cost-effective, you often will want to use several value chains simultaneously. This tool will tell you whether you can do that or not.”

The tool, Gyuk said, “goes on models. There is a lot of modeling information. And that modeling information is beginning to be validated by applications that we actually build.”

ES-Select also allows a user to derive a cost estimate for a selected storage technology, at a selected scale. “Not in a numbers way,” Gyuk explained. Instead, “it will give you a range of benefits for the storage application.”

Any kind of storage can be complementary to renewables, Gyuk said, but conditions for renewable and storage technologies vary by site and scale, so “giving people a number is not really a good way to do it. It is better to give them a range. If they are on the high side, it’s probably not cost-effective. If their particular niche is on the low side, then it will be.”

Gyuk has spent a decade studying energy storage systems and is “familiar with virtually the entire storage industry.” The thing these new tools demonstrate most clearly, he said, is that “energy storage is working its way toward maturity.”